In the oil and gas industry, the oil well product refers to a gas and liquid mixed fluid simultaneously comprising liquid crude oil, water and natural gas, and the liquid and gas mixed liquid is called as “multiphase fluid” in the art. Said gas phase includes, for example, oil field gas or any gases which are non-condensable at room temperature, for example, such as methane, ethane, propane, butane and the like, and said liquid phase includes an oil phase, e.g., crude oil and other liquid additives which are dissolved in crude oil during the exploration of crude oil, and a water phase, e.g., formation water, water which is injected into oil wells during the exploration, and other liquid additives which are dissolved in the water phase. In practice, the phase separation between the oil phase and the water phase may occur, and it is also possible that the oil phase and the water phase are mixed together or entirely emulsified. How to real-time and accurately measure the gas flowrate and liquid flowrate in the gas and liquid mixed liquid explored from oil wells and how to further measure the flowrates of the oil, gas and water phases are essential for production management and production optimization. When the mass fraction of gas phase in a multiphase fluid is higher than 80%, the multiphase fluid is customarily called as “wet gas”. Materials that explored from submarine oil and gas fields and shale all are wet gases.
When the oil well is a high-pressure well, the wellhead pressure is in an order of magnitude of tens of MPa. In order to control throughput of oil wells and wellhead pressure, an oil nozzle, as a throttling device, is widely used in petroleum chemistry. In practice, the oil nozzle is not only used as a device for control throughput of oil wells, but also required by customers to have a metering function.
In the prior art, the method for measuring respective flowrates of gas phase and liquid phase in a multiphase fluid is to combine a Venturi flowmeter and gamma ray technology, and its principals are described as follows: a Venturi tube is utilized to measure the total volume flowrate of a wet gas, and a single-energy gamma-ray detector is used to measure the respective phase fractions of the gas and liquid phases therein; then, the total volume flowrate multiplies by the respective phase fractions of the gas phase and liquid phase to calculate the respective volume flowrates thereof. However, at the throat of the oil nozzle, the fluid flows in a sonic speed, and the principles of the Venturi pressure difference method are not applicable for metering the fluid flows in a sonic speed.
In current oil fields, nozzles have already been at wellheads, and through the wellheads, subterranean crude oil is ejected. Through long-term production practices, it has been recognized that there are some formulae for showing the quantitative and empirical relations of flowrate of crude oil at these nozzles with the pressure difference ΔP between the pressure P1 (in oil fields, called as “oil pressure”) at the nozzle inlet and the pressure P2 (in oil fields, called as “back pressure”) at the nozzle outlet, and the formulae can be useful for approximately estimating the crude oil flowrate. However, such a metering method will involve significant errors. Further, another method that is an actual measuring method during well testing, in which upon testing wells, by measuring pressure and temperature and after separating oil well products, a gas phase and a liquid phase are respectively metered, and then the resultant data is fitted. Such a method is not applicable for long-term applications, because the pressure of the oil wells and the gas mass fraction of the gas phase in the crude oil dynamically vary in a life cycle, and if only a changeless metering equation is used, it will result in significant errors, even misjudge the throughput of the oil wells.
Additionally, it is found that on the precondition that the oil pressure P1 is essentially changeless, when the pressure difference ΔP gradually rises, the total flowrate Q will also gradually rise; however, when the pressure difference ΔP reaches and exceeds a certain critical value ΔPc, the flowrate Q will not change with the change of the ΔP, but be maintained at a stable value without any further changes. Such a state is called as the critical flow state.
Hence, people utilize an oil nozzle to control the throughput of oil wells and the wellhead pressure with the desire the oil nozzle is also able to meter products. However, current oil nozzles have very limited metering functions, and thus they cannot achieve the precise and real-time metering of the respective mass flowrates of the gas phase and liquid phase in a multiphase fluid.